Schlumberger, the assignee of the present application, has recently introduced Downhole Fluid Analysis (DFA) to the petroleum industry. The first commercial services of DFA are the LFA (Live Fluid Analyzer) and the CFA (Compositional Fluid Analyzer). DFA provides identification of fluid variations in real time during openhole wireline logging, enabling efficient fluid characterization and corresponding optimization of sample acquisition. DFA has contributed to the finding that hydrocarbons are often compositionally varied, not homogeneously distributed in the formation as had often been presumed.
A known problem in the petroleum industry is the identification of compartments. Currently, the routine and standard industry practice to identify compartments is to establish pressure communication. The lack of pressure communication indeed identifies separate compartments. However, the pressure equilibration in geologic time does not establish flow communication in production time. Specifically, the mismatch can be approximately 9 orders of magnitude, which is a major reason compartment identification is one of the biggest problems in the industry today.
Using DFA, it has been found that different compartments often contain different hydrocarbons. In fact, geoscientific arguments can be advanced predicting the routine observation of hydrocarbon fluid density inversions in different compartments. It is, for example, known that thermogenic gas is generally deep while heavy oil is generally shallow. Using DFA, it has become known that the large scale density inversion can project over distances as little as 6 feet.
Currently, DFA is performed on openhole and cased hole sampling tools that form a seal around a section of the borehole wall, or around the casing containing one or more holes. Thus, fluids currently contained in the formation are brought into the interior of the analysis tool where DFA is performed. As a result, measurements are restricted to station measurements.
It is highly desirable to perform DFA in a continuous manner of producing wells for at least the following reasons.
It is known that gravity, thermal gradients, biodegradation, water stripping, leaky seals, realtime charging, multiple charging, and miscible sweep fluid injection all contribute to compositional variation. It is also known that gravity and thermal gradients move a column towards equilibrium. However, modeling is totally unreliable for factors moving the hydrocarbons towards disequilibrium. Consequently, optimal production mandates extensive data acquisition. That is, spatial variation of hydrocarbons in the reservoir dictates time dependent hydrocarbon properties in production, which can have significant implications in production optimization. For example, the GOR of produced fluids will vary during production. If the GOR increases due to drainage of higher GOR volumes, or due to break through of (miscible) gas injection, then the gas handling capabilities of existing facilities can be exceeded. Therefore, production, and thus the oil flow rate must be reduced. Moreover, because gas is often reinjected it would be desirable to identify what zones are producing high gas cut fluids. Of course, the gas might be dissolved downhole. Reduction of production from these zones would enable increased oil flow.
In addition, production around phase transitions is complicated. For retrograde dew fields, for example, it can be optimal to produce below dew point, with concomitant gas reinjection to effectively blow dry the formations. Thus, it would be highly desirable to measure the condensate-gas ratio as a function of depth in the formation.
It is also known that the production of dry gas would mean that gas is simply being circulated indicating that production should be terminated. Use of N2 as a pressure maintenance fluid (as is done in large fields in Mexico) mandates detection of dissolved N2 to understand reservoir dynamics. Moreover, C02 vs. CH4 production can vary substantially zone by zone and can change with time. H2S production is highly variable spatially and temporally from different zones. It is essential that the resultant surface H2S concentration not exceed specifications of existing facilities. Thus, identification and production reduction of offending zones is critical to optimal production.
Aquifer drive coupled with water injection is routinely performed in the industry. There is a very important issue associated with aquifer connectivity. Obviously, water injection wells must target the appropriate water zones for efficient sweep. Determination of water zone connectivity can be performed with water analysis. For example, pH is a sensitive determinant for distinguishing waters. pH cannot be measured properly in the lab for oil field waters due to lab requirements of low pressure and temperature. Thus, measuring pH downhole is an excellent method to address water zone connectivity.
In addition to measuring compositional information, one could imagine capturing a sample and modifying it to measure a transition pressure (or temperature). For example, a sample of light oil could be transferred to a cell where the pressure can be adjusted, allowing for the monitoring of the dew point. Information related to the dew point is important in that if the production pressure for a fluid is set incorrectly, the dew might be dropped in the formation. Given that gas has a higher mobility and thus flows preferentially, measuring the dew point pressure in production logging (PL) would help guide production parameters such as the appropriate production pressures.
Measuring asphaltene onset pressures can also be important. Specifically, it can be important to adjust pressures to control the physical location of asphaltene flocculation to avoid, for example, asphaltene flocculation in the formation. To this end, optimal pressure selection aided by the proper and accurate information obtained during production logging would allow for better production without phase behavior problems, as well as the addition of treatment chemicals when necessary, which is far more effective if confined to the borehole.
It is desirable, therefore, to have a Production Logging (PL) tool that includes sensors to measure physical and chemical properties of formation fluids in real time during the logging run.